This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Extended Reach Drilling (ERD) often reduces field development costs for hydrocarbons because it allows remote reserves to be accessed from a surface location that allows a lower-cost drilling unit to be used than would be required to drill a vertical well to the hydrocarbon reservoir. For example, a significant portion of the Chayvo field in Russia has been developed using a land-based rig to drill more than 15 10-km-throw wells (“throw” is the horizontal distance from surface to bottom-hole location) rather than drilling from a more costly offshore Arctic drilling platform. The current reach (throw) record of a well is about 12 km, but 15-km-reach wells are reportedly being planned. There is a growing need to dramatically increase the reach capability for ERD even beyond 15 km. For example, for a deepwater prospect in the Arctic, in an area where crushing sea ice may limit seasonal drilling windows to a few weeks per year, it may take two or three years to drill a well. This significantly hurts the economics of the prospect. If the heart of the prospect is about 30 km away from shallow (<60 m) water, for example, an ERD well with a throw of 30 km drilled from a bottom-founded platform that allows year-round drilling could significantly improve the economics of appraising and developing the field. In fact, 30-km ERD capability could potentially be enabling for field development.
There are two main technical challenges in constructing long ERD wells: (1) torque and drag forces on the drill string and (2) equivalent circulating density (ECD) of the drilling fluid (mud). Torque and drag can be reduced by rotating the drill string, using lighter-weight materials for the tubulars, floating-in casing and liners, adding lubricants in the surrounding fluid and/or using mechanical devices (e.g., roller centralizers). By one or combinations of such techniques, based on results from ERD wells and predictive calculations, torque and drag can be controlled such that it does not limit ERD in many environments, even to a throw of 30 km or more.
The limiting parameter in drilling many ERD wells is “delta ECD.” The pressure outside the bit required to flow the mud back to the surface is called “Equivalent Circulating Density” (ECD). As the well measured depth increases and as the casing/liner strings get smaller, the ECD increases even more above the pressure that would be exerted outside the bit if the mud were not circulating. This increase, called here “delta ECD,” is caused by fluid frictional pressure. The delta ECD in some ERD wells while drilling 8½-inch hole through 9 km of 9⅝-inch casing was measured at about 4 ppg (pounds per gallon). Based on this, for a similar geometry, a 30-km well would have more than 12 ppg in delta ECD, which is unacceptably high. If the ECD is too high, the well will lose returns and cuttings will build up, eventually causing the Bottom Hole Assembly (BHA) to become stuck. This is a costly problem that typically would cause the well to be abandoned. The ECD issue can be mitigated by using liners, but typically the liners would have to be set in a full casing string (typically 13⅜-inch OD) that could withstand kick pressures. The reduced ID of the full casing string compared to the conductor means that ECD would likely still be a major problem.
Others have tried to solve the delta ECD problem in a variety of manners, for example, using well architecture to maximize the annular area, reducing the viscosity of the mud, using managed pressure drilling, using a downhole pump incorporated into the drill string, and using various forms of “dual gradient” drilling. Well architecture may maximize the size of the annular area. This will reduce the annular fluid frictional pressure losses, but drilling large diameter wells have several drawbacks. Using small diameter drill pipe also has drawbacks.
Generally, using a low viscosity mud will reduce ECDs. Several approaches have been tried, including using mud weighted with micro-sized barite rather than conventional sized barite, but lower viscosity mud reduces hole-cleaning effectiveness.
Managed Pressure Drilling (MPD) is a technique whereby the return mud flows through a choke that provides a back pressure on the annulus. This allows a lighter mud weight to be used. Generally muds with lower densities have lower viscosities, and thus the delta ECD can be somewhat reduced. However, MPD is complicated and expensive to implement.
At least one service company has performed research on a downhole annular mud pump that is incorporated into the drill string, which is described in “A Downhole Tool for Reducing ECD,” Amer. Association of Drilling Engineers, AADE-07-NTCE-69 (2007). In this apparatus, the pump takes suction from the mud below the pump and pumps the annular fluid above the pump to the surface. This reduces the pressure seen by the formation at total depth (TD). The idea of using a pump to reduce the pressure at TD has merit, but incorporating a pump into the drill string is fraught with problems. First, when pulling upwards, the pump may create a swab pressure that may induce wellbore instability or formation fluid influx. Second, the pump represents a potential hazard to well control because it cannot be easily stripped through the blowout preventers. Also, the current design uses the downward fluid flow as an energy source to drive the pump, and this saps horsepower from the rig pumps. In addition, the pump must be placed inside casing and has rotating seals that are a prime failure point.
There have been a number of attempts to reduce annular pressures (and therefore ECDs) in deepwater wells using the concept of dual gradient drilling (DGD). In DGD, pumping is used to help lift the mud returns from the sea floor. In some cases, pumps placed either on or near the sea floor or suspended in the water column are used to lift the mud back to the rig. For example, Smith et. al. (SPE 71357) describe a subsea mud lift system for reducing annular mud pressures. This system incorporates a mud pump that is placed on the sea floor. U.S. Pat. No. 6,854,532 discloses a suction pump coupled to the annulus. Examples of suspended pump systems include the Ocean Riser Drilling System discussed by Fossli (SPE 91633). Other DGD methods include injecting a lightweight fluid (sometimes containing hollow beads) into the drilling riser above the blowout preventer (BOP) (e.g., SPE 99135). These systems often use the riser boost line or a concentric riser string to pump into the return mud stream and inject a lightweight gas or liquid.
The DGD systems can lower the bottomhole pressure and ECD by lowering pressure at the mudline, but the bottomhole pressure will still be affected by the long interval (measured depth) below the mudline in ERD wells, i.e., by the annular frictional pressure losses from the bottom of the borehole to the mudline.
What is needed is apparatus and method for decreasing the ECD in long ERD wells. The method should be applicable in onshore or offshore wells in any water depth.
It is also desirable to provide extended horizontal reach such that the location of a drilling or other operations vessel or facility and the subsea bottom-surface location of a well each may be remotely placed from each other to permit continuous year-around or extended working seasons in the wellbore from the facility. Previously known technology may relegate vessel or facility locations to areas that are subject to sea ice, especially icebergs, that limit arctic well operations to intermittent or seasonal activities.
The foregoing discussion of need in the art is intended to be representative rather than exhaustive.